Published in Petroleum Transactions, AIME, Volume 217, 1959, pages 1–8. Abstract This paper presents results of an experimental investigation of factors that control the efficiency with which oil is displaced from porous media by a miscible fluid. The study was made to elucidate the relevant processes both on microscopic level (within individual or between neighboring pore spaces) and on macroscopic level (within a large sand body). Mixing of miscible fluids on the microscopic level was studied in sand-packed tubes. It was found that molecular diffusion is the dominant dispersion mechanism for reservoir conditions of rate, length and pore sizes. Macroscopic channeling was studied for various mobility ratios in reservoir models-scaled to relate viscous gravitational, and diffusional forces. The formation of channels was due to viscous fingering, gravity segregation and variations in permeability. With adverse mobility ratios, it was found for reservoirs of realistic widths that diffusion will not be effective in preventing the formation and growth of fingers, even in homogeneous sands. At sufficiently low rates channeling was eliminated by gravity segregation in tilted reservoirs. The dependence of recovery on mobility ratio, length-to-width ratio, flow rate and angle of dip is presented. Introduction Oil recovery by solvent flooding is finding increasing application in the field. while the process promises high recoveries from the region swept by solvent, under adverse conditions only a small fraction of the reservoir volume may be swept at the time solvent breaks through to the producing well. Further, the high cost of the solvent encourages its use only as a bank whose size must be kept at a minimum. Thus, two important questions arise:what fraction of the reservoir can be swept, practically, by solvent? andwhat is the minimum size solvent bank that can be used to carry out the displacement? The answers to these questions require knowledge of both macroscopic channeling processes and microscopic mixing processes. The studies described here were carried out to gain this knowledge. Microscopic mechanisms which cause mixing will be discussed first, because an understanding of these mechanisms is necessary for proper interpretation of the experimental work on channeling described later.
A new hydraulic fracturing system has been developed and tested in both oil and gas wells. The fluids used are viscous polymer emulsions made from commonly available lease fluids such as crude oil and brine. By varying the oil and polymer content, the properties of the system can be easily controlled. Relative to other viscous fluid systems, for comparable results the costs are much less. Summary and Conclusions In the past 5 years, viscous fracturing fluids have been shown to have advantages over conventional, low-viscosity gelled-water fluids. Many viscous fluid systems were developed and tested with various degrees of success. The main limitations of those fluids are their high cost and, in some instances, the difficulty of removing the fluid from the formation.A new hydraulic fracturing system has been developed and tested under a variety of field conditions in both oil and gas wells. Fluids used in this system are viscous emulsions prepared with a lease crude, refined oil, condensate or liquefied petroleum gas as the internal phase, and water, brine, or acid containing a water-soluble polymer and a surfactant as the external phase. This adaptable fluid system is inexpensive, its properties can be controlled, and it breaks readily after the treatment, permitting the injected fluids to be easily produced from the formation.Properties of these emulsion fluids are controlled by varying the polymer concentration in the water and the volume of oil in the emulsion. Sufficient polymer is used to provide the aqueous phase with an polymer is used to provide the aqueous phase with an apparent viscosity from 10 to 100 cp at 75 degrees F and at a shear rate of 511 sec(-1). The concentration of the dispersed oil phase is maintained between 50 and 80 volume percent.For field applications, the preferred emulsion contains from 60 to 75 volume percent oil and from 1 to 2 lb of guar per barrel of water or brine. This composition is generally chosen since it can be emulsified easily and allows for a margin of mixing error. The fluid viscosity will be too low if the oil content is 50 percent or less, and the emulsion may become unstable or too viscous if the oil content is greater than 80 percent.A surface-active emulsifier capable of forming an oil-in-water emulsion is added to the aqueous phase at a concentration of about 0.5 percent by weight to help form the emulsion and temporarily stabilize its properties. The two basic types of surfactants used properties. The two basic types of surfactants used for this application are sodium tallate (for fresh water) and a quaternary amine (for brine; i.e., water containing more than 10,000 ppm chlorides). A fluid loss additive (FLA) - normally a mixture of silica flour and a commercial additive composed of particles coated with a water-soluble polymer - may be added at a concentration of 20 to 40 lb per 1,000 gal of emulsion.Polymer emulsion fracturing resulted in an average production increase of 3.4 for 97 Exxon Co. U.S.A. production increase of 3.4 for 97 Exxon Co. U.S.A. oil and gas wells treated in 1971 and 1972. Clean-up after these treatments was rapid and most gas wells were placed back on production without swabbing. P. 731
Published in Petroleum Transactions, Volume 219, 1960, pages 293–300. Abstract This paper presents the results of a laboratory investigation of the efficiency of water-solvent mixtures in recovery of oil. These mixtures may have the high displacement efficiencies characteristic of solvent floods and the high sweep efficiencies characteristic of water floods. Thus, the water-solvent process may increase the number of reservoirs in which a miscible-type displacement can be used profitably. The experiments on the use of water-solvent mixtures for recovery of oil were conducted to find the general applicability of the process. These studies demonstrated that, in flowing through sands, water and solvent segregated into a solvent layer on the top and a water layer on the bottom rather than flowing through the sands as a uniform mixture. Calculations based on the simultaneous flow of the water and solvent in layers were used to predict the effective mobility of the mixtures and the optimum operation of the process in steeply dipping, homogeneous reservoirs. As most reservoirs are not suited for the operation of the process under ideal conditions, experimental studies were conducted with sand-packed models scaled to represent more realistic reservoirs. These studies included the effects on recovery of oil of rate of injection, viscosity of oil, variations of permeability within a formation and variations in water-solvent ratio. For the range of conditions studied, higher recoveries of oil were obtained with water-solvent mixtures than with water or practical volumes of solvent alone. Introduction A group of intriguing-because of their great possibilities - new oil recovery methods at the disposal of the petroleum engineer are the miscible displacement processes. These processes (high-pressure gas drive, enriched-gas drive and LPG bank driven by methane) displace all of the oil from the portions of the reservoir swept by the injection fluid. The key question confronting the engineer applying one of these techniques to a particular reservoir is, "What fraction of the reservoir can be swept by injection of a practical volume of solvent?".
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